Natural gas mainly consists of methane which is also accompanied by other substances, some of which are of a similar nature, i.e. organic, while others are completely different and influence the properties of the natural gas accordingly. Depending on its geological source, a natural gas can also contain a disruptive concentration of acid gas components which must be separated before the natural gas can be made available for commercial use. The extent to which a component is deemed to interfere depends on the individual component. CO.sub.2 is often tolerated up to approx. 2% by vol. H.sub.2 S is highly toxic, and at the high pressure levels used for handling natural gas, even low concentrations can cause harmful corrosion. This can ultimately lead to hydrogen-induced stress crack corrosion which can cause gas pipelines to burst. Therefore, as a rule, only a few ppm can be permitted. The allowable limit for less harmful organic sulfur compounds, which are also formed in small quantities when H.sub.2 S and CO.sub.2 are present, is usually higher by 1 to 2 powers of ten.
The use of formylmorpholine (NFM) as an absorbent for H.sub.2 S and CO.sub.2 is known from U.S. Pat. No. 3,773,896. 70 to 80% of the absorbed sulfur compounds and 55 to 65% of the absorbed CO.sub.2 can be separated from the absorbent using thermal regeneration at a temperature of 80.degree. C. The limited desorption of the dissolved gas from the loaded absorbent has a detrimental effect as the gas portions remaining in the solution impede the absorption of the gases from the raw gas and do not allow any low residual concentrations in the treated gas. Furthermore, separation of the acid gas components requires higher absorbent circulation.
A large number of other physical absorbents and chemical absorbents for separating CO.sub.2 and H.sub.2 O from industrial gases, especially from natural gases, are known (A. Kohl et al., "Gas Purification", 4th edition 1985; Stephen A. Newman, "Acid and Sour Gas Treating Processes", Gulf Publishing Comp., 1985). Physical absorbents include selexol, propylene carbonate and methanol. One disadvantage of these common absorbents is, however, that a considerable portion of useful components is also absorbed from the gas. This especially applies to natural gases from which methane and higher hydrocarbons are also absorbed. Part of the hydrocarbons dissolved in the absorbent can be released by flashing and then recovered by compressing the gas stream released during flashing and recycling it to the raw gas stream prior to its entry into the absorber. Recycling, however, requires additional energy for the compression of the gas stream and enlarges the volume flow passed on to the absorber. As a result, the energy efficiency ratio of the process deteriorates. Chemical absorbents include ethanolamines and alkali salt solutions. Chemical absorbents require considerably more energy for regeneration than physical absorbents, and it is not economically feasible to use them for the removal of organic sulfur compounds from raw gas. Furthermore, some chemical absorbents are very corrosive so that corrosion inhibitors have to be added or plants have to be fabricated from special anticorrosive materials.
When natural gases with a high CO.sub.2 content, which can be as high as 40% by vol., are treated, correspondingly large amounts of released CO.sub.2 are obtained and passed into underground gas holders, usually at a pressure of 200 to 400 bar to prevent emissions. The acid gas obtained during desorption, which has a pressure of 1 to 2 bar, is compressed in compressors until it reaches the pressure required for the aquifer storage. Operating and investment costs can be reduced if the acid gases can be separated from the absorbent at a higher working pressure.